Transcript NERC GADS 101 Data Reporting Workshop: Presented by Mike

NERC GADS 101
Data Reporting Workshop
G. Michael Curley
Manager of GADS Services
October 27-29, 2010
Welcome
 GADS Services Staff
• Mike Curley – Manager of GADS Services
• Joanne Rura – GADS Services Coordinator
• Ronald Niebo – Reliability Assessment and Performance
Analysis Coordinator
 Please stand and introduce yourselves
• Your name, company, and experience with GADS
2
Overview of Attendees at this Conference
 Representatives of:
• Generating companies (IOU, IPPs, Government, etc)
• Consultants
• Insurance
• ISOs
3
What’s in the folder?
 Agenda
 List of attendees (as of October 20, 2010)
 Changes to the 2011 DRI
 Slides for GADS 101 Data Reporting Workshop
 Slides for GADS Wind Data Reporting Workshop
 Slides for Benchmarking Seminar
 Slides for pc-GAR and pc-GAR MT Workshop
 Slides for Unit Design Data Entry Program
 Flash drive
4
What’s on the flash drive?
Same as the folder plus …
 GADS Data Reporting Instructions (effective January 1, 2011)
 GADS Data Editing Program
 GADS Services Pricing Schedule
 pc-GAR and pc-GAR MT Demo Software
 pc-GAR Order Forms
 GADS Wind Turbine Generation Data Reporting Instructions
 GADS Wind Generation Data Entry Software
 WEC Studies
5
Agenda
 Introduction and welcoming remarks
• What is NERC?
• What is GADS?
 Fundamentals on the three GADS Databases
 Event
What are the elements of the event database?
 Performance
What are the elements of the performance database?
 Design
What makes up the design database?
6
Agenda (cont.)
 IEEE 762 Equations and their meanings
• What are the equations calculated by GADS?
• What are they trying to tell you?
• Review of standard terms and equations used by the
electric industry.
 Data release policies
 What’s new with GADS?
 Closing Comments
7
NERC is the ERO
8
NERC Background
 NERC started in 1968.
 NERC chosen as the ERO for the US in 2006. Started
developing the “Rules of Procedure” to manage the bulk
power supply.
 BPS consists of the transmission and generation
facilities.
 NERC changed from “council” to “corporation” in January
2007.
 From 2007 to now, NERC became the ERO of 6 of the
10 Canadian Provinces.
9
Energy Policy Act of 2005
 Signed by President Bush in August 2005
 The reliability legislation amends Part II of the Federal
Power Act to add a section 215 making reliability standards
for the bulk- power system mandatory and enforceable.
 Electric Reliability Organization (ERO)
• Not a governmental agency or department
 Same purpose: “To keep the lights on” but with more
power to do so.
10
Energy Policy Act of 2005
 “Bulk-power System” means the facilities and
control systems necessary for operating an
interconnected electric energy transmission
network (or any portion thereof) and electric
energy from generation facilities needed to
maintain transmission system reliability. The
term does not include facilities used in the local
distribution of electric energy.
11
About NERC
International regulatory authority for electric
reliability in North America
 Develop & enforce reliability standards
 Analyze system outages and near-misses
& recommend improved practices
 Assess current and future reliability
12
Meeting Demand in Real Time
Typical Daily Demand Curve
Operating Reserves
Peak Load
Intermediate Load
Capacity:
Instantaneous measure of
electricity available at peak
Base Load
Energy:
Electricity Produced over Time
13
About NERC: Regional Entities (RE)
Florida Reliability Coordinating Council
Midwest Reliability Organization
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool, Reliability Entity
Texas Regional Entity
Western Electricity Coordinating Council
14
What does NERC do?
 Sets reliability standards (96 in place; 24 being reviewed)
 Monitors compliance with reliability standards
 Provides education and training resources
 Conducts reliability assessments
 Facilitates reliability information exchange
 Supports reliable system operation and planning
 Certifies reliability organizations and personnel
 Coordinates security of bulk electric system
• Cyber attacks
• Pandemics
• Geomagnetic disturbances
15
One of the first orders of business…
 Create a transmission database
• Transmission Availability Data System (TADS)
• 200 kV and above.
• Currently 2 years of data in TADS
16
Work now…
 Marry the transmission to the generation
databases, using Section 1600 of the Rules of
Procedure.
17
GADS Task Force
 Talked about mandatory GADS reporting for
many years.
 In June 2010, the NERC Planning Committee
(PC) approved a task force to determine if
GADS should be mandatory and to what level.
• About 77% of the installed capacity already report to
GADS.
• Voluntary database now.
 To date, the GADSTF is recommending
mandatory reporting of GADS data.
18
Rules of Procedure: Section 1600
Overview
 NERC’s authority to issue a mandatory data request in
the U.S. is contained in FERC’s rules. Volume 18 C.F.R.
Section 39.2(d) states: “Each user, owner or operator of
the Bulk-Power System within the United States (other
than Alaska and Hawaii) shall provide the Commission,
the Electric Reliability Organization and the applicable
Regional Entity such information as is necessary to
implement section 215 of the Federal Power Act as
determined by the Commission and set out in the Rules
of Procedure of the Electric Reliability Organization and
each applicable Regional Entity.”
19
Rules of Procedure: Section 1600
Request Details
 A complete data request includes:
• a description of the data or information to be requested, how the
data or information will be used, and how the availability of the
data or information is necessary for NERC to meet its obligations
under applicable laws and agreements
• a description of how the data or information will be collected and
validated
• a description of the entities (by functional class and jurisdiction)
that will be required to provide the data or information (“reporting
entities”)
• the schedule or due date for the data or information
• a description of any restrictions on disseminating the data or
information (e.g., “confidential,” “critical energy infrastructure
information,” “aggregating” or “identity masking”)
• an estimate of the relative burden imposed on the reporting
entities to accommodate the data or information request
20
Rules of Procedure: Section 1600
Procedure
NERC Approval Committees
Acting
Subgroup
Not Approved
Submit
Data
Request
to PC
Submit
Data
Request
to DCS
Draft
Data
Request
Not Approved
FERC Comment Period Public Comment Period
Collect,
Respond, &
Post
Comments
Post Data
Request
(45 Days)
File Data
Request
(21 Days)
Affected Parties
NERC Board of Trustees
Submit
Final Data
Request
Finalize
Data
Request
No Appeal
Submit
Data
Request
Data Rule
In Effect
Approved
Appeal
(30 Days)
21
Not Approved
Rules of Procedure: Section 1600
Limitations
 NERC Registered Entities
 Subject to FERC Rules
• Data Request does not carry the same penalties to
non-U.S. entities.
• However, all NERC Registered Entities, regardless of
their country of origin, must comply with the NERC
Rules of Procedure, and as such, are required to
comply with Section 1600
22
What if a GO doesn’t comply?
 Possible NERC actions:
• From Rule 1603: “Owners, operators, and users of
the bulk power system registered on the NERC
Compliance Registry shall comply with authorized
requests for data and information.” The data request
must identify which functional categories are required
to comply with the request. In this case, it presumably
would be Generation Owners.
23
What if a GO doesn’t comply?
 Possible NERC actions:
• NERC will audit the GADS data submittals through
logical evaluations of the data reported and that
previously reported by the entity. Reconciliation
findings will be reviewed with the reporting entity.
24
What if a GO doesn’t comply?
 Possible NERC actions:
• NERC may resort to a referral to FERC for only United
States entities, not Canadian entities. NERC will make
use of the mechanisms it has available for both U.S. and
Canadian entities (notices, letters to CEO, requests to
trade associations for assistance, peer pressure) to gain
compliance with the NERC Rules. A failure to comply
with NERC Rules could also be grounds for suspension
or disqualification from membership in NERC. Whether
or not NERC chooses to use that mechanism will likely
depend on the facts and circumstances of the case.
• NERC cannot impose penalties for a failure to
comply with a data request.
25
What if a GO doesn’t comply?
 Possible FERC actions:
• All members of NERC (US and Canadian) are bound
by their membership agreement with NERC to follow
NERC’s Reliability Standards and Rules of Procedure,
including section 1600.
• Under section 215 of the Federal Power Act, FERC has
jurisdiction over all users, owners, and operators of the
bulk power system within the United States.
• FERC could treat a failure by a U.S. entity to comply
with an approved data request as a violation of a rule
adopted under the Federal Power Act using its
enforcement mechanisms in Part III of the FPA.
26
What if a GO doesn’t comply?
 What about Canada?
• Canadian provinces who have signed agreements
stating they recognize NERC’s ERO status, will be
compliant with the NERC approved standards and
Rules of Procedure issued by the NERC Board.
• The obligation arises for the Canadian utilities if they
are members of NERC. For example, if Canadian
Utility “A” is a member of NERC, then it must go by
the Rules of Procedure, standards, etc. If Canadian
Utility “X” is not a NERC member but its providence
recognizes NERC as their ERO, then Utility “X” is not
under obligation to follow the rules.
27
GADS vs. ISO Data Collection Rules
 Currently, GADS sets data collection rules for
use on a national basis; each ISO can set the
rule for data collection within their jurisdiction.
 Here are special rules that GADS suggests for
hydro units.
• As of August 5, 2008 we considered a draft of the rules.
• A more “final set of rules” is now Appendix M of the
GADS Data Reporting Instructions issued January 2010.
 One recommendation of GADSTF is one set of
rules for all (coordination between GADS and
ISOs).
28
More information?
 Please visit our website: www.nerc.com
 Most information is open to the public.
29
Question & Answer
30
What is GADS?
G - Generating
A - Availability
D - Data
S - System
31
What is GADS?
 Analyze the past (1982-2009)
• Conduct special studies like high impact/low
probability (HILP) studies
• Perform benchmarking services
 Monitor the present (2010 data)
• Track current unit performance
 Assess the future
• Predict the future performance of units
32
Example – Benchmarking – Distributions
Example of EAF Distribution
100
Cumulative Percent, %
90
80
70
60
50
40
30
20
10
0
50
55
60
65
70
75
80
85
90
95
100
Equivalent Availability Factor (EAF)
[Fossil-steam units 200-400MW; Coal fuel; 6,500+ Service Hours/Yr.;
2005-2009; (79 units from 73 companies)]
33
Example – Benchmarking – Top Problems
[Fossil-steam units 200-400MW; Coal fuel; 6,500+ Service Hours/Yr.;
2005-2009; (79 units from 73 companies)]
34
What is meant by “Availability?”
 GADS maintains a history of actual
generation, potential generation and
equipment outages.
 Not interested in dispatch requirements or
needs by the system!
 ** If the unit is not available to produce 100%
load, we want to know why!
35
Monitor the Present
Generator
“C”
Generator
“D”
Generator
“B”
Generator
“A”
GADS
Generator
“E”
5,800+ generating units including 2 international affiliates.
36
International GADS Users
 Malaysia *
 Peoples Republic of China
 Ireland *
 Spain
 Brazil *
 New Zealand
 India *
 South Korea
 Parts of S. America
* Are or soon will be reporting outage data to GADS.
37
GADS 2009 Data Reporting
6000
5500
5000
4500
4000
3500
3000
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
5,874 units reported in 2009, 0.9% increase in the
number of units reporting over 2008!
38
Why GADS?
 Provide NERC committees with information on
availability of power plant for analyzing grid
reliability and national security issues.
 Provide energy marketers with data on the
reliability of power units.
 Assist planning of future facilities.
 Help in setting goals for production and
maintenance.
39
Why GADS?
 Evaluating new equipment products and plant
designs.
 Assisting in prioritizing repairs for overhauls.
 Help planners with outage down timing and
costs.
 Provide insights on equipment problems and
preventative outages.
40
Why GADS?
 Benchmarking existing units to peers.
 Provide a source of backup data for insurance,
governmental inquiries and investigations, and
lose of hard drives.
 Working to find answers to questions not asked.
• Economic dispatch records
• Generation owners in several regions
• Track units bought and sold
41
Question & Answer
42
The GADS Data Monster
43
The GADS Databases
 Design – equipment descriptions such as
manufacturers, number of BFP, steam turbine
MW rating, etc.
 Performance – summaries of generation
produced, fuels units, start ups, etc.
 Event – description of equipment failures such
as when the event started/ended, type of outage
(forced, maintenance, planned), etc.
44
Design Data Reporting (Section V)
45
Why collect design data?
 For use in identifying the type of unit (fossil,
nuclear, gas turbine, etc).
 Allows selection of design characteristics
necessary for analyzing event and performance
data.
 Provides the opportunity to critique past and
present fuels, improvements in design,
manufacturers, etc.
46
Unit Types (Appendix C)
Unit Type
Fossil (Steam)
(use 600-649 if additional numbers are needed)
Nuclear
Combustion Turbines
(Use 700-799 if additional numbers are needed)
Diesel Engines
Hydro/Pumped Storage
(Use 900-999 if additional numbers are needed)
Fluidized Bed Combustion
Miscellaneous
(Multi-Boiler/Multi-Turbine, Geothermal, Combined Cycle Block, etc.)
Coding Series
100-199
200-299
300-399
499-499
500-599
650-699
800-899
47
Minimum Design Data for Editing
 Utility (Company) Code
 Unit Code
 NERC Region
 Date of commercial operation
• Reaching 50% of its generator nameplate MW
capacity
• Turned over to dispatch (enters “active state”)
 Nameplate rating of unit (permanent)
 State location
48
Design Data Forms
 Forms are located in Appendix E
 Complete forms when:
• Utility begins participating in GADS
• Unit starts commercial operation
• Unit’s design parameters change such as a new
FGD system, replace the boiler, etc.
49
Example of Design Data Form
50
Performance Reporting (Section IV)
51
Why collect performance records?
 Collect generation of unit on a monthly basis.
 Provide a secondary source of checking event
data.
 Allows analysis of fuels
52
Performance Report
 “05” Format (new)
• More accurate with 2 decimal places for capacities,
generation and hours.
• Collects inactive hours (discussed later)
• As of January 1, 2010, GADS only accepts the new
format.
53
Performance Records
General Overview:
 Provides summary of unit operation during a
particular month of the year.
• Actual Generation
• Hours of operation, outage, etc.
 Submitted quarterly for each month of the year.
• Within 30 days after the end of the quarter
54
Unit Identification
 Record Code – the “05” uniquely identifies
the data as a performance report (required)
 Utility (Company) Code – a three-digit code
that identifies the reporting organization
(required)
 Unit Code – a three-digit code that identifies
the unit being reported. This code also
distinguishes one unit from another in your
utility (required)
55
Unit Identification (cont.)
 Year – is the year of the performance record
(required)
 Report Period – is the month (required)
 Report Revision Code – shows changes to the
performance record (required)
• Original Reports (0)
• Additions or corrections (1, 2,…9)
• Report all records to a performance report if you
revise just one of the records.
56
Unit Generation
 Six data elements
 Capacities and generation of the unit during the
report period.
 Can report both gross and net capacities.
• Net is preferred
• Missing Net or Gross capacities will be calculated!
57
Unit Generation (cont.)
 Gross Maximum Capacity (GMC)
• Maximum sustainable capacity (no derates)
• Proven by testing
• Capacity not affected by equipment unless permanently
modified
 Gross Dependable Capacity (GDC)
• Level sustained during period without equipment, operating
or regulatory restrictions
 Gross Actual Generation
• Power generated before auxiliaries
58
Unit Generation (cont.)
 Net Maximum Capacity (NMC)
• GMC less any capacity utilized for unit’s station services
(no derates).
• Capacity not affected by equipment unless permanently
modified.
 Net Dependable Capacity (NDC)
• GDC less any capacity utilized for that unit’s station
services.
 Net Actual Generation
• Power generated after auxiliaries.
• Can be negative if more aux than gross!
59
Gas Turbine/Jet Capacities
 GT & Jets capacities do not remain as constant
as fossil/nuclear units.
 ISO standard for the unit (STP -- based on
environment) should be the GMC/NMC
measure.
 Output less than ISO number is unit GDC/NDC.
 Average capacity number for month is reported
to GADS
60
Effect of Ambient Temperature
61
Maximum and Dependable Capacity
 What is the difference between
Maximum and Dependable?
• GMC - GDC = Ambient Losses
• NMC - NDC = Ambient Losses
62
Missing Capacity Calculation!
 If any capacity (capacities) is (are) not reported,
the missing capacities will be calculated based
on all reported numbers.
 For example, if only the NDC is reported and the
NDC = 50, then:
• NDC = NMC = 50
• GMC = NMC times (1 + factor)
• GDC = NDC times (1 + factor)
• GAG = NAG times (1 + factor)
63
Missing Capacity Calculation!
 Factors are based on data reported to GADS in
1998 as follows:
Unit Type
Difference
Fossil, Nuclear, and Fluidized Bed:
5.0% difference between gross and net values
Gas Turbine/Jet Engine:
2.0% difference between gross and net values
Diesel:
No difference between gross and net values
Hydro/Pumped Storage:
2.0% difference between gross and net values
Miscellaneous:
4.0% difference between gross and net values
64
Missing Capacity Calculation!
 If any capacity (capacities) is (are) not reported,
the missing capacities will be calculated based
on all reported numbers
 For example, if only the GDC is reported and the
GDC = 50, then:
• GDC = GMC = 50
• NMC = GMC times (1 - factor)
• NDC = GDC times (1 - factor)
• NAG = GAG times (1 – factor)
65
Missing Capacity Calculation!
 Capacities are needed to edit and calculate unit
performances.
 If you don’t like the new capacities or
generation numbers calculated, then complete
the RIGHT number in the reports. GADS will not
overwrite existing numbers!
66
Quick Quiz
Question:
Suppose your utility only collects net generation
numbers. What should you do with the gross generation
fields?
67
Quick Quiz (cont.)
Answer:
Leave the field blank or place asterisks (*) in the gross
max, gross dependable, and gross generation fields.
The editing program recognizes the blank field or the *
and will look only to the net sections for data.
68
Unit Loading
Typical Unit Loading Characteristics
Code
Description
1
Base loaded with minor load-following at night and on weekends
2
Periodic startups with daily load-following and reduced load nightly
3
Weekly startup with daily load-following and reduced load nightly
4
Daily startup with daily load-following and taken off-line nightly
5
Startup chiefly to meet daily peaks
6
Other (see verbal description)
7
Seasonal Operation (winter or summer only)
69
Attempted & Actual Unit Starts
 Attempted Unit Starts
• Attempts to synchronize the unit
• Repeated failures for the same cause without
attempted corrective actions are considered a single
start
• Repeated initiations of the starting sequence without
accomplishing corrective repairs are counted as a
single attempt.
• For each repair, report 1 attempted starts.
 Actual Unit Starts
• Unit actually synchronized to the grid
70
Attempted & Actual Unit Starts (cont.)
 If you report actual start, you must report
attempted.
 If you do not keep track then:
• Leave Starts Blank
• GADS editor will estimate both attempted and actual
starts based on event data.
 The GADS program also accepts “0” in the
attempts field if actual = 0 also.
71
Unit Time Information
 Service Hours (SH)
• Number of hours synchronized to system
 Reserve Shutdown Hours (RSH)
• Available for load but not used (economic)
72
Unit Time Information (cont.)
 Pumping Hours
• Hours the hydro turbine/generator operated as a
pump/motor
 Synchronous Condensing Hours
• Unit operated in synchronous mode
• Hydro, pumped storage, gas turbine, and jet engines
 Available Hours (AH)
• Sum of SH+RSH+Pumping Hours+ synchronous
condensing hours
73
Question & Answer
74
Unit Time Information (cont.)
 Planned Outage Hours (POH)
• Outage planned “Well in Advance” such as the annual unit
overhaul.
• Predetermined duration.
• Can slide PO if approved by ISO, Power Pool or dispatch
 Forced Outage Hours (FOH)
• Requires the unit to be removed from service before the end of
the next weekend (before Sunday 2400 hours)
 Maintenance Outage Hours (MOH)
• Outage deferred beyond the end of the next weekend (after
Sunday 2400 hours).
75
Unit Time Information (cont.)
 Extensions of Scheduled Outages
(ME, PE)
• Includes extensions from MOH & POH beyond its
estimate completion date or predetermined duration.
• Extension is part of original scope of work and
problems encountered during the PO or MO.
• If problems not part of OSW, then extended time is a
forced outage.
• ISO and power pools must be notified in advance of
any extensions whether ME, PE, or U1.
76
Unit Time Information (cont.)
 Unavailable Hours (UAH)
• Sum of POH+FOH+MOH+PE+ME
 Period Hours or Active (PH)
• Sum of Available + Unavailable Hours
 Inactive Hours (IH)
• The number of hours the unit is in the inactive state
(Inactive Reserve, Mothballed, or Retired.)
• Discussed later in detail.
77
Unit Time Information (cont.)
 Calendar Hours
• Sum of Period Hours + Inactive Hours
• For most cases, Period Hours = Calendar Hours
78
Quick Quiz
Question:
The GADS editing program will only accept 744 hours
for January, March, May, etc; 720 hours for June,
September, etc; 672 for February. (It also adjusts for
daylight savings time.) But there are two exceptions
where it will let you report any number of hours in the
month. What are these?
79
Quick Quiz (cont.)
Answer:
 When a unit goes commercial. The program checks
the design data for the date of commercial operation and
will accept any data after that point.
 When the unit retires or is taken out of service for
several years, the GADS staff must modify the
performance files to allow the data to pass the edits.
80
Quick Quiz (cont.)
Question (3 answers):
Suppose you receive a performance error message for
your 500 MW NMC unit that states you reported 315,600
MW of generation but the GADS editing program states
the generation should only be 313,000 MW? You
reported 625 SH, 75 RSH, and 44 MO.
• Hint: {[NMC+1] x (SH)] + 10%}
81
Quick Quiz (cont.)
Answers:

Check the generation of the unit to make sure it is
315,600 MW

Check the Service Hours of the unit. It is best to round
a fraction of an hour up then to round it down.
• 625.4 hours => 626 hours

Check the NMC of the unit. You can adjust it each
month.
82
Primary Fuel
 Can report from one to four fuels
 Primary (most thermal BTU) fuel
 Not required for hydro/pumped storage units
 Required for all other units, whether operated or
not
83
Primary Fuel (cont.)
 Fuel Code (required)
 Quantity Burned (optional)
 Average Heat Content (optional)
 % Ash (optional)
 %Moisture (optional)
 % Sulfur (optional)
 % Alkalis (optional)
 Grindability Index (coal only)/
% Vanadium and Phosphorous (oil only) - (optional)
 Ash Softening Temperature (optional)
84
Fuel Codes
Fuel Codes
Code
Description
Code
Description
CC
Coal
PR
Propane
LI
Lignite
SL
Sludge Gas
PE
Peat
GE
Geothermal
WD
Wood
NU
Nuclear
OO
Oil
WM
Wind
DI
Distillate oil
SO
Solar
KE
Kerosene
WH
Waste Heat
JP
JP4 or JP5
OS
Other – Solid (Tons)
WA
Water
OL
Other – Liquid (BBL)
GG
Gas
OG
Other – Gas (Cu. Ft.)
85
Question & Answer
86
Quick Quiz
Question:
Utility “X” reported the following data for the month of
January for their gas turbine Jumbo #1:
• Service Hours: 4
• Reserve Shutdown Hours: 739
• Forced Outage Hours: 1
• Fuel type: NU
Any problems with this report?
87
Quick Quiz (cont.)
Answer:
There is no such thing as a nuclear powered gas
turbine!
88
Quick Quiz (cont.)
Question:
Suppose you operate a gas turbine that has 100 NMC in
the winter (per the ISO charts).
During the winter months, you can produce 100 MW
NDC. What is your season derating on this unit during
the winter?
89
Quick Quiz (cont.)
Answer:
There is no derating!
•
NMC – NDC = 100 – 100 = 0 (zero)
90
Quick Quiz (cont.)
Question:
Suppose you operate a gas turbine that has 100 NMC in
the winter (per the ISO charts) and 95 NMC in the
summer (per the ISO charts).
During the summer months, you can produce 95 NDC.
What is your season derating on this unit during the
summer?
91
Quick Quiz (cont.)
Answer:
There is no derating!
•
NMC – NDC = 95 – 95 = 0 (zero)
ISO charts and operating experience determine
capability of GTs and other units. DO NOT ASSUME
ALL GT OPERATE AT SAME CAPACITY YEAR
AROUND!
(Winter NMC = Summer NMC for GTs)
92
Event Reporting (Section III)
93
Why Collect Event Records?
 Track problems at your plant for your use.
 Track problems at your plant for others use.
 Provide proof of unit outages (ISO, PUC,
consumers groups, etc).
 Provide histories of equipment for “lessons
learned.”
 Provide planning with data for determining length
and depth of next/future outages.
94
The “Ouch” Factor
 Non-IEEE or any other term
 A description of what is the maximum information
you can gather from a power generator before
they yell “ouch!”
 GADS is at the maximum Ouch Factor at this
time.
95
Event Identification
 Record Code – the “07” uniquely identifies
the data as an event report (required)
 Utility (Company) Code – a three-digit code
that identifies the reporting organization
(required)
 Unit Code – a three-digit code that identifies
the unit being reported. This code also
distinguishes one unit from another in your
utility (required)
96
Event Identification (cont.)
 Year – the year the event occurred (required)
 Event Number – unique number for each event
(required)
• One event number per outage/derating
• Need not be sequential
• Events that continue through multiple months keeps
the originally assigned number
97
One Event for One Outage
Event 1
Month 1
Event 1
Event 1
Month 2
Month 3
Event 1
98
Quick Quiz
Question:
Some generators report a new event record for
the same event if it goes from one month to the
next or goes from one quarter to the next.
What are the advantages of such actions to the
GADS statistics?
99
Quick Quiz (cont.)
Answer:
None!
• This action distorts the frequency calculation of
outages.
• Increase the work load of the reporter by having them
repeat reports.
• Increases the chances of errors in performance and
event records
 Hours of outage
 Cause codes and event types
100
GADS is a DYNAMIC System
Make as many changes as you want,
as many times as you want,
whenever you want.
101
Report Year-to-date!
 Report all data year-to-date with the revision
code zero “0” again.
• If any other changes were made, the reporters and
NERC databases would always be the same.
• It is easier and better to replace the entire database
then to append one quarter to the next.
102
Event Identification (cont.)
 Report Revision Code – shows changes to
the event record (required)
• Original Reports (0)
• Additions or corrections (1, 2,…9)
• Report all records to a performance report if you
revise just one of the records.
 Event Type – describes the event experienced
by the unit (required)
• Inactive
• Active
103
Unit States
104
Unit States – Inactive
105
Unit States – Inactive (cont.)
 Inactive
• Deactivated shutdown (IEEE 762) as “the State in
which a unit is unavailable for service for an extended
period of time for reasons not related to the
equipment.”
• IEEE and GADS interprets this as Inactive Reserve,
Mothballed, or Retired
106
Unit States – Inactive (cont.)
 Inactive Reserve (IR)
• The State in which a unit is unavailable for service but
can be brought back into service after some repairs in
a relatively short duration of time, typically measured
in days.
• This does not include units that may be idle because
of a failure and dispatch did not call for operation.
• The unit must be on RS a minimum of 60 days before
it can move to IR status.
• Use Cause Code “0002” (three zeros plus 2) for these
events.
107
Unit States – Inactive (cont.)
 Mothballed (MB)
• The State in which a unit is unavailable for service but
can be brought back into service after some repairs
with appropriate amount of notification, typically weeks
or months.
• A unit that is not operable or is not capable of
operation at a moments notice must be on a forced,
maintenance or planned outage and remain on that
outage for at least 60 days before it is moved to the
MB state.
• Use Cause Code “9991” for these events.
108
Unit States – Inactive (cont.)
 Retired (RU)
• The State in which a unit is unavailable for service and
is not expected to return to service in the future.
• RU should be the last event for the remainder of the
year (up through December 31 at 2400). The unit must
not be reported to GADS in any future submittals.
• Use Cause Code “9990” for these events.
109
Unit States – Active
110
Event Identification (cont.)
 Event Type (required -- 17 choices)
• Two-character code describes the event (outage,
derating, reserve shutdown, or noncurtailing).
EVENT TYPES
OUTAGES
DERATINGS
PO – Planned
PD – Planned
PE – Planned Extension
DP – Planned Extension
MO – Maintenance
D4 – Maintenance
ME – Maintenance Extension
DM – Maintenance Extension
SF – Startup Failure
D1 – Forced - Immediate
U1 – Forced - Immediate
D2 – Forced - Delayed
U2 – Forced - Delayed
D3 – Forced - Postponed
U3 – Forced Postponed
RS – Reserve Shutdown
NC – Non Curtailing
111
Unit States – Active (cont.)
 What is an outage?
• An outage starts when the unit is either
desynchronized (breakers open) from the grid or when
it moves from one unit state to another
• An outage ends when the unit is synchronized
(breakers are closed) to the grid or moves to another
unit state.
• In moving from one outage to the next, the time
(month, day, hour, minute) must be exactly the same!
112
From the Unit States Diagram
“Unplanned”
Forced + Maintenance + Planned
113
From the Unit States Diagram
“Scheduled”
Forced + Maintenance + Planned
114
Unit States – Active (cont.)
 Scheduled-type Outages
• Planned Outage (PO)
 Outage planned “Well in Advance” such as the annual unit overhaul.
 Predetermined duration.
 Can slide PO if approved by ISO, Power Pool or dispatch
• Maintenance (MO) - deferred beyond the end of the
next weekend but before the next planned event
(Sunday 2400 hours)
 If an outage occurs before Friday at 2400 hours, the above definition
applies.
 But if the outage occurs after Friday at 2400 hours and before
Sunday at 2400 hours, the MO will only apply if the outage can be
delayed passed the next, not current, weekend.
 If the outage can not be deferred, the outage shall be a forced event.
115
Unit States – Active (cont.)
 Scheduled-type Outages
• Planned Extension (PE) – continuation of a planned
outage.
• Maintenance Extension (ME) – continuation of a
maintenance outage.
116
Unit States – Active (cont.)
Extension valid only if:
 All work during PO and MO events are determined in
advance and is referred to as the “original scope of
work.”
 Do not use PE or ME in those instances where
unexpected problems or conditions discovered during the
outage that result in a longer outage time.
 PE or ME must start at the same time
(month/day/hour/minute) that the PO or MO ended.
117
PE or ME on January 1 at 00:00
 Edit program checks to make sure an extension
(PE or ME) is preceded by a PO or MO event.
 Create a PO or MO event for one minute before
the PE or ME.
• Start of Event: 01010000
• End of Event: 01010001
118
Unit States – Active (cont.)
 Forced-type Outages
• Immediate (U1) – requires immediate removal from
service, another Outage State, or a Reserve Shutdown
state. This type of outage usually results from immediate
mechanical/electrical/hydraulic control systems trips and
operator-initiated trips in response to unit alarms.
• Delayed (U2) – not required immediate removal from
service, but requires removal within six (6) hours. This
type of outage can only occur while the unit is in service.
• Postponed (U3) – postponed beyond six (6) hours, but
requires removal from service before the end of the next
weekend
119
Unit States – Active (cont.)
 Forced-type Outages
• Startup Failure (SF) – unable to synchronize within a
specified period of time or abort startup for repairs.
Startup procedure ends when the breakers are closed.
120
Example #1 – Simple Outage
Event Description:
On January 3 at 4:30 a.m., Riverglenn #1 tripped off line
due to high turbine vibration.
The cause was the failure of an LP turbine bearing (Cause
Code 4240).
The unit synchronized on January 8 at 5:00 p.m.
121
Example #1 – Simple Outage
700
Capacity (MW)
600
500
400
Forced Outage
CC 4240
300
200
100
0
0
1
2
Jan 3 @ 0430
3
4
5
6
Jan 8 @ 1700
122
Scenario #1: FO or MO?
 There was a tube leak in the boiler 4 days
before the scheduled PO. (Normal repair time is
36 hours.)
 The unit cannot stay on line until the next
Monday and must come down within 6 hours.
 Dispatch cleared the unit to come off early for
repairs and PO.
 What type of outage is this?
123
Scenario #1: FO or MO?
 There was a tube leak in the boiler 4 days
before the scheduled PO. (Normal repair time is
36 hours.)
 The unit cannot stay on line until the next
Monday and must come down within 6 hours.
 Dispatch cleared the unit to come off early for
repairs and PO.
 What type of outage is this?
 Answer: First 36 hours to fix tube leak (U2) then
change to PO. Why?
124
Scenario #1: FO or MO?
 There was a tube leak in the boiler 4 days before the
scheduled PO. (Normal repair time is 36 hours.)
 The unit cannot stay on line until the next Monday and
must come down within 6 hours.
 Dispatch cleared the unit to come off early for repairs and
PO.
 What type of outage is this?
 Answer: whether or not the unit is scheduled for PO, it
must come down for repairs before the end of the next
weekend. After the repair, the PO can begin!
125
Scenario #2: FO or MO?
 Vibration on unit’s ID Fan started on Thursday
10 a.m.
 The unit could stay on line until the next Monday
but dispatch says you can come off Friday
morning. On Friday, the dispatch reviewed the
request and allowed unit to come off for repairs.
 What type of outage is this?
126
Scenario #2: FO or MO?
 Vibration on unit’s ID Fan started on Thursday
10 a.m.
 The unit could stay on line until the next Monday
but dispatch says you can come off Friday
morning. On Friday, the dispatch reviewed the
request and allowed unit to come off for repairs.
 What type of outage is this?
 Answer: MO. Why?
127
Scenario #2: FO or MO?
 Vibration on unit’s ID Fan started on Thursday
10 a.m.
 The unit could stay on line until the next Monday
but dispatch says you can come off Friday
morning. On Friday, the dispatch reviewed the
request and allowed unit to come off for repairs.
 What type of outage is this?
 Answer: The unit could have stayed on line until
the end of the next weekend if required.
128
Scenario #3: FO or MO?
 Gas turbine started vibrating and vibration
increased until after peak period. The GT had to
come off before the end of the weekend.
 Dispatch said GT would not be needed until the
next Monday afternoon.
 What type of outage is this?
129
Scenario #3: FO or MO?
 Gas turbine started vibrating and vibration
increased until after peak period. The GT had to
come off before the end of the weekend.
 Dispatch said GT would not be needed until the
next Monday afternoon.
 What type of outage is this?
 Answer: FO. Why?
130
Scenario #3: FO or MO?
 Gas turbine started vibrating and vibration
increased until after peak period. The GT had to
come off before the end of the weekend.
 Dispatch said GT would not be needed until the
next Monday afternoon.
 What type of outage is this?
 Answer: the GT is not operable until the vibration
is repaired. It could not wait until after the
following weekend.
131
Scenario #4: FO or RS?
 It’s Monday. Combined cycle had a HRSG tube
leak and must come off line now. It is 2x1 with no
by-pass capabilities.
 Dispatch said CC was not needed for remainder of
week.
 Management decided to repair the unit on regular
maintenance time. Over the next 36 hours, the
HRSG was repaired. Normal HRSG repairs take 12
hours of maintenance time.
 What type of outage is this and for how long?
132
Scenario #4: FO or RS?
 It’s Monday. Combined cycle had a HRSG tube leak
and must come off line now. It is 2x1 with no by-pass
capabilities.
 Dispatch said CC was not needed for remainder of week.
 Management decided to repair the unit on regular
maintenance time. Over the next 36 hours, the HRSG
was repaired. Normal HRSG repairs take 12 hours of
maintenance time.
 What type of outage is this and for how long?
 Answer: FO as long as the unit is not operable – full 36
hours. Then RS (CA).
133
Scenario #5: PE or FO?
 During 4 week PO, repairs on Electrostatic
Precipitator (ESP) were more extensive then
planned.
 At the end of 4 week, the ESP work is not
completed as outlined in the original scope of
work. 3 more days is required to complete the
work.
 What type of outage is the extra 3 days?
134
Scenario #5: PE or FO?
 During 4 week PO, repairs on Electrostatic
Precipitator (ESP) were more extensive then
planned.
 At the end of 4 week, the ESP work is not
completed as outlined in the original scope of
work. 3 more days is required to complete the
work.
 What type of outage is the extra 3 days?
 Answer: SE. Why?
135
Scenario #5: PE or FO?
 During 4 week PO, repairs on Electrostatic
Precipitator (ESP) were more extensive then
planned.
 At the end of 4 week, the ESP work is not
completed as outlined in the original scope of
work. 3 more days is required to complete the
work.
 What type of outage is the extra 3 days?
 Answer: ESP work was part of the original scope
of work.
136
Scenario #6: ME or FO?
 During 4 week MO, mechanics discovered
Startup BFP seals needed replacing. (not part of
scope.)
 At the end of 4 week, the SBPF work was not
completed because of no parts on site. 12 hour
delay in startup to complete work on SBFP.
 What type of outage is the extra 12 hours?
137
Scenario #6: ME or FO?
 During 4 week MO, mechanics discovered
Startup BFP seals needed replacing. (not part of
scope.)
 At the end of 4 week, the SBPF work was not
completed because of no parts on site. 12 hour
delay in startup to complete work on SBFP.
 What type of outage is the extra 12 hours?
 Answer: FO. Why?
138
Scenario #6: ME or FO?
 During 4 week MO, mechanics discovered
Startup BFP seals needed replacing. (not part of
scope.)
 At the end of 4 week, the SBPF work was not
completed because of no parts on site. 12 hour
delay in startup to complete work on SBFP.
 What type of outage is the extra 12 hours?
 Answer: No part of original scope and delayed
startup by 12 hours.
139
Scenario #7: PO or FO?
 During the 4 week PO, mechanics discovered
ID fan blades needed replacement (outside the
scope).
 Parts were ordered and ID fan was repaired
within the 4 week period. No delays in startup.
 Does the outage change from PO to FO and then
back to PO due to unscheduled work?
140
Scenario #7: PO or FO?
 During the 4 week PO, mechanics discovered
ID fan blades needed replacement (outside the
scope).
 Parts were ordered and ID fan was repaired
within the 4 week period. No delays in startup.
 Does the outage change from PO to FO and then
back to PO due to unscheduled work?
 Answer: remains PO for full time. Why?
141
Scenario #7: PO or FO?
 During the 4 week PO, mechanics discovered
ID fan blades needed replacement (outside the
scope).
 Parts were ordered and ID fan was repaired
within the 4 week period. No delays in startup.
 Does the outage change from PO to FO and then
back to PO due to unscheduled work?
 Answer: work completed with scheduled PO
time.
142
More Examples?
Appendix G – Examples and Recommended
Methods
Reporting Outages to the Generating Availability
Data System (GADS)
143
A Word of Experience …
 IEEE definitions are designed to be guidelines
and are interpreted by GADS.
 We ask all reporters to follow the guidelines so
that uniformity is reporting and resulting
statistics.
 If a unit outage is determined to be a MO, it is an
MO by IEEE Guidelines.
• If a unit needs to come off and is not allowed to, more
damage to the equipment and longer outages will be
the result. (Investigation from Southern Co.)
144
Testing Following Outages
 On-line testing (synchronized)
• In testing at a reduced load following a PO, MO, or
FO, report the derating as a PD, D4 or the respective
forced-type derating
• Report all generation
 Off-line testing (not synchronized)
• Report testing in “Additional Cause of Event or
Components Worked on During Event”
• Can report as a separate event
145
Black Start Testing
 A black start test is a verification that a CT unit
can start without any auxiliary power from the
grid and can close the generator breaker onto a
dead line or grid.
 To set up the test, you isolate the station from
the grid, de-energize a line, and then give the
command for the CT to start. If the start is
successful, then you close the breaker onto the
dead line. Once completed, you take the unit off,
and re-establish the line and aux power to the
station.
 You coordinate this test with the transmission
line operator, and it is conducted annually.
146
Black Start Testing (cont.)
 GADS Services surveyed the industry and it was
concluded that:
• It is not an outside management control event.
• It can be a forced, maintenance or planned event.
• Use the new cause code 9998.
147
Any questions about outages?
148
Unit States (Deratings)
 What is a derate?
• A derate starts when the unit is not capable of
reaching 100% capacity.
• A derate ends when the equipment is either ready for
or put back in service.
• An capacity is based on the capability of the unit, not
on dispatch requirements.
• More than one derate can occur at a time.
149
Unit States (Deratings)
 Report a derate or not?
• If the derate is less than 2% NMC AND last less than
30 minutes, then it is optional whether you report it or
not.
• All other derates shall be reported!
 Report a 1-hour derate with 1% reduction
 Report a 15-minute derate with a 50% reduction.
150
Unit Capacity Levels
 Deratings
• Ambient-related
Losses are not
reported as deratings report on Performance
Record (NMC-NDC)
• System Dispatch
requirements are not
reported
151
Unit States – Active
 Forced Deratings
• Immediate (D1) – requires immediate reduction in
capacity.
• Delayed (D2) – does not require an immediate
reduction in capacity but requires a reduction within
six (6) hours.
• Postponed (D3) – can be postponed beyond six (6)
hours, but requires reduction in capacity before the
end of the next weekend.
152
Unit States – Active (cont.)
 Scheduled Deratings
• Planned (PD) – scheduled “well in advance” and is of
a predetermined duration.
• Maintenance (D4) – deferred beyond the end of the
next weekend but before the next planned derate
(Sunday 2400 Hours).
153
Unit States – Active (cont.)
 Scheduled Deratings (cont.)
• Planned Extension (DP) – continuation of a planned
derate.
• Maintenance Extension (DM) – continuation of a
maintenance derate.
154
Unit States – Active (cont.)
Extension valid only if:
 All work during PD and D4 events are determined
in advance and is referred to as the “original
scope of work.”
 Do not use DP or DM in those instances where
unexpected problems or conditions discovered
during the outage that result in a longer derating
time.
 DP or DM must start at the same time
(month/day/hour/minute) that the PD or D4 ended.
155
Unit Capacity Levels
Maximum Capacity
Seasonal Derating = Maximum Capacity - Dependable Capacity
Dependable Capacity
Basic Planned Derating
Extended Planned Derating
Planned
Derating
Unit Derating=
D1
D2
Dependable Capacity - Available capacity
Unplanned
Derating
D3
Maintenance
Available Capacity
Note: All capacity and deratings are to be expressed on either
gross or net basis.
156
Example #2 – Simple Derating
Event Description:
On January 10 at 8:00 a.m., Riverglenn #1 reduced
capacity by 250 MW due to a fouled north air preheater,
leaving a Net Available Capacity (NAC) of 450 MW.
Fouling began two days earlier, but the unit stayed on line
at full capacity to meet load demand.
Repair crews completed their work and the unit came back
to full load [700 MW Net Maximum Capacity (NMC)] on
January 11 at 4:00 p.m. The Net Dependable Capacity
(NDC) of the unit is also 700 MW.
157
Example #2 – Simple Derating
700
600
Derating
500
400
300
200
100
0
0
1
Jan 10 @ 0800
2
3
4
5
6
Jan 11 @1600
158
Unit Deratings
 Deratings that vary in magnitude
• New event for each change in capacity or,
• Average the capacity over the full derating time.
159
Unit Deratings
 Overlapping Deratings
• All deratings are additive unless shadowed by an outage or larger
derating.
• Shadowed derating are Noncurtailing on overall unit performance
but retained for cause code summaries.
• Can report shadowed deratings
• Deratings during load-following must be reported.
• GADS computer programs automatically increase available
capacity as derating ends.
• If two deratings occur at once, choose primary derating; other as
shadow.
160
Example #3 - Overlapping Deratings
Second Starts & Ends Before First (G-3A)
Event Description:
Riverglenn #1 had an immediate 100 MW derating on
March 9 at 8:45 a.m. due to a failure of the ‘A’ pulverizer
feeder motor. Net Available Capacity (NAC) is 500 MW.
At 10:00 a.m. the same day, another 100 MW (NAC = 500
MW) loss occurs with the failure of ‘B’ pulverizer mill. Failure
of the ‘B’ mill is repaired after 1 hour when a foreign object is
removed from the mill.
The ‘A’ motor is repaired and returned to service on March 9
at 6:00 p.m.
161
Example #3 - Overlapping Deratings
Second Starts & Ends Before First (G-3A)
Capacity (MW)
700
Forced Derating
CC 0250
600
D1 CC0320
500
400
300
200
100
0
0
1
3/9@:0845
2
3/9@1000
3
4
3/9@1100
5
6
3/9@1800
162
Dominant Derating Code
 All deratings remain as being additive unless
modifier marked as “D”
 Derating modifier marks derating as being
dominate, even if another derating is occurring
at the same time.
 No affect on unit statistics.
 Affects cause code impact reports only.
163
Example #4 - Overlapping Derating
(2nd is Shadowed by the 1st) (G-3B)
Event Description:
Riverglenn #1 had a D4 event on July 3 at 2:30 p.m. from
a condenser maintenance item that reduced the NAC to
590 MW. Fouled condenser tubes (tube side) were the
culprit.
Maintenance work began on July 5 at 8 a.m. and the
event ended on July 23 at 11:45 a.m.
On July 19 at 11:45 a.m., a feedwater pump tripped,
reducing the NAC and load to 400 MW. This minor repair
to the feedwater pump was completed at noon that same
164
day.
Example #4 - Overlapping Derating
(1st is Shadowed by the 2nd) with Dominant Code
700
Capacity (MW)
D4
CC 3112
600
500
D1 CC 3410
400
300
200
100
0
0
1
7/3@1430
2
7/19@1115
3
4
7/19@1200
5
6
7/23@1145
165
Dominant Derating Code
700
Capacity (MW)
Event #1
Event #3
D4
CC 3112
600
D1 CC3410
500
Event #2
400
Without Dominant Derating Code
300
3 events to cover 2 incidents
700
Capacity (MW)
Event #1
Event #2
D4 CC 3112
600
500
D1 CC3410
400
300
With Dominant Derating Code
2 events to cover 2 incidents
166
Dominant Derating Code (cont.)
 How do you know if a derating is dominant?
• If you’re not sure, ask!
 Control room operator
 Plant engineer
• If you don’t mark it dominant, the software will assume
it is additive. That can result in inaccurate reporting.
167
Dominant Derating Code (cont.)
 The following slides show you what happens
behind the scenes. However, you do not have to
program these derates. They are done
automatically for you by your software.
 All you have to do is indicate that the problem is
dominate.
168
Dominant Derating Code (cont.)
Normal Deratings
Event 1
Event 2
169
Dominant Derating Code (cont.)
Single Dominant Derating
Dominant
Derating –
Event 3
170
Dominant Derating Code (cont.)
Overlapping Dominant Deratings
Dominant
Derating –
Event 4
Dominant
Derating –
Event 3
Dominant Derating 3 SHADOWS portion of Event 4
171
Dominant Derating Code (cont.)
Overlapping Dominant Deratings by Virtue of Loss
Dominant
Derating –
Event 3
Derating –
Event 4
Derating –
Event 4 takes the
dominant
position.
172
Dominant Derating Code (cont.)
 Advantages are:
• Shows true impact of equipment outages for big,
impact problems
• Reduces reporting on equipment
• Shows true frequency of outages.
173
Deratings During Reserve Shutdowns
 Simple Rules:
 Maintenance work performed during RS where
work can be stopped or completed without
preventing the unit from startup or reaching its
available capacity is not a derating - report on
Section D.
 Otherwise, report as a derating. Estimate the
available capacity.
174
Coast Down or Ramp Up From Outage
• If the unit is coasting to an outage in normal time
period, no derating.
• If the unit is ramping up within normal time
(determined by operators), no derating!
• Nuclear coast down is not a derating UNLESS the unit
cannot recover to 100% load as demanded.
175
Any questions about deratings?
176
Other Unit States
 Reserve Shutdown – unit not synchronized but
ready for startup and load as required.
 Noncurtailing – equipment or major component
removed from service for maintenance/testing
and does not result in a unit outage or derating.
 Rata testing?
 Generator Doble testing?
177
Question & Answer
178
Event Magnitude
 Impact of the event on the unit
 4 elements per record:
• Start of event
• End of event
• Gross derating level
• Net derating level
 If you do not report gross or net levels, it will be
calculated!
179
Unit Capacity Levels
Maximum Capacity
Seasonal Derating = Maximum Capacity - Dependable Capacity
Dependable Capacity
Basic Planned Derating
Extended Planned Derating
Planned
Derating
Unit Derating=
D1
D2
Dependable Capacity - Available capacity
Unplanned
Derating
D3
Maintenance
Available Capacity
Note: All capacity and deratings are to be expressed on either
gross or net basis.
180
Missing Capacity Calculation!
 Factors are based on data reported to GADS in
1998 as follows:
• Fossil units –> 0.05
• Nuclear units –> 0.05
• Gas turbines/jets –> 0.02
• Diesel units –> 0.00
• Hydro/pumped storage units –> 0.02
• Miscellaneous units –> 0.04
 Unless …
181
Missing Capacity Calculation!
 We can use the delta (difference) between your
gross and net capacities from your performance
records as reported by you to calculate the
differences between GAC and NAC on your
event records!
182
Event Magnitude (cont.)
 Start of Event (required)
• Start month, start day
• Start hour, start minute
 Outages start when unit was desynchronized or
enters a new outage state
 Deratings start when major component or
equipment taken from service
 Use 24-hour clock!
183
Event Magnitude (cont.)
 End of Event (required by year’s end)
• End month, end day
• End hour, end minute
 Outage ends when unit is synchronized or,
placed in another outage state
 Derating ends when major component or,
equipment is available for service
 Again, use 24-hour clock
184
Using the 24-hour Clock
 If the event starts at midnight, use:
• 0000 as the start hour and start time
 If the event ends at midnight, use:
• 2400 as the end hour and end time
185
Event Transitions (Page III-24)
 There are selected outages that can be
back-to-back; others cannot.
 Related events are indicated by a “yes”; all
others are not acceptable.
186
Event Transitions (cont.)
Allowable Event Type Changes
FROM
TO
U1
U2
U3
SF
MO
PO
ME
PE
RS
U1 - Immediate
Yes
No
No
Yes
Yes
Yes
No
No
Yes
U2 – Delayed
Yes
No
No
Yes
Yes
Yes
No
No
Yes
U3 – Postponed
Yes
No
No
Yes
Yes
Yes
No
No
Yes
SF - Startup Failure
Yes
No
No
Yes
Yes
Yes
No
No
Yes
MO – Maintenance
Yes
No
No
Yes
Yes
Yes
Yes
No
Yes
PO – Planned
Yes
No
No
Yes
No
Yes
No
Yes
Yes
ME – Maintenance Extension
Yes
No
No
Yes
No
No
Yes
No
Yes
PE – Planned Extension
Yes
No
No
Yes
No
No
No
Yes
Yes
RS – Reserve Shutdown
Yes
No
No
Yes
Yes
Yes
No
No
Yes
187
Question & Answer
188
Quick Quiz
Question:
Riverglenn #1 reported Event #14 (a Planned Outage PO) from June 3 at 01:00 to July 5 at 03:45. Event
#17 is a Unplanned Forced - Delayed (U2) Outage
from July 5 at 03:45 to July 5 at 11:23 due to
instrumentation calibration errors.
Are these events reported correctly?
189
Quick Quiz (cont.)
Answer:
No! The transition from an outage type where the unit
out of service to an outage type where the unit is inservice is impossible.
Question:
How do you fix these events?
190
Quick Quiz (cont.)
Answer:
Change the U2 to an SF
191
Quick Quiz (cont.)
Question:
Your unit is coming off line for a planned outage. You
are decreasing the load on your unit at a normal rate
until the unit is off line.
Is the time from the when you started to come off line
until the breakers are opened a derate?
192
Quick Quiz (cont.)
Answer:
No. Why?
Standard operating procedure. By NERC’s standards,
it is not a derate.
193
Quick Quiz (cont.)
Question:
You have finished the planned outage and you are
coming up on load. The breakers are closed and you are
ramping up at a normal pace. You are able to reach full
load in the normal ramp up time (including stops for heat
sinking and chemistry.)
Is this a derate?
194
Quick Quiz (cont.)
Answer:
No! All ramp up and safety checks are all with the
normal time for the unit.
195
Quick Quiz (cont.)
Question:
You have finished the planned outage and you are
coming up on load. The breakers are closed and you are
ramping up at a normal pace. But because of some
abnormal chemistry problems, you are not able to reach
full load in the normal ramp up time. It takes you 5 extra
hours.
Is this a derate?
196
Quick Quiz (cont.)
Answer:
Yes. The 5 hours should be marked as a derate at the
level you are stalled. Once the chemistry is corrected and
you can go to full load, then the derate ends.
197
Question & Answer
198
Primary Event Cause
 Details of the primary cause of event
• What caused the outage/derate?
• May not always be the root cause
199
Primary Event Cause
 Described by using cause code
• 4-digit number (See Appendix B)
• 1,600+ cause codes currently in GADS
• Points to equipment problem or cause, not a detailed
reason for the outage/derate!
• Set of cause codes for each type of unit.
 Cause codes for fossil-steam units only
 Cause codes for hydro units only
200
Set of Cause Codes for Each Unit Type
 Fossil
 Gas Turbine
 Fluidized Bed Fossil
 Jet Engine
 Nuclear
 Combined Cycle &
Co-generator
 Diesel
 Hydro/Pumped Storage
 Geothermal
201
Set of Cause Codes for Each Unit Type
 Example of two names, different units:
 Fossil-steam
• 0580 - Desuperheater/attemperator piping
• 0590 - Desuperheater/attemperator valves
 Combined cycle
• 6140 - HP Desuperheater/attemperator piping Greater than 600 PSIG.
• 6141 - HP Desuperheater/attemperator valves
202
Cause Codes for Internal Economics
 Document specific demand periods verses
“average” differences for a month.
 Want to calculate EAF and NCF differences for
any period of time.
 NOT REPORTED TO GADS!
 20 cause codes (9180 to 9199) set up.
203
What is Amplification Code?
 Alpha character to describe the failure mode or
reason for failure (Appendix J)
 Located in blank column next to cc.
 Used by CEA and IAEA as modifiers to codes for
many years.
 Increases the resources of cause codes without
adding new codes.
 Many same as Failure Mechanisms (Appendix H)
 This is voluntary but important.
204
Example of Amplification Code
 C0 = Cleaning
 E0 = Emission/environmental restriction
 F0 = Fouling
 45 = Explosion
 53 = Inspection, license, insurance
 54 = Leakage
 P0 = Personnel error
 R0 = Fire
205
Example of Amplification Code
 Boiler (feedwater) pump packing leak.
• Cause code 3410; amp code “54”
 HP Turbine buckets or blades corrosion
• Cause code 4012; amp code “F0”
 Operator accidentally tripped circulating water
pump
• Cause code 3210; amp code “P0”
206
Event Contribution Codes
 Contribution Codes
1
Primary cause of event – there can only be one primary cause
for forced outages. There can be multiple primary causes for
PO and MO events only.
2
Contributed to primary cause of event – contributed but not
primary.
3
Work done during the event – worked on during event but did
not initiate event.
5
After startup, delayed unit from reaching load point
Note: No codes 6 or 7 as of January 1, 1996
207
Event Contribution Codes (cont.)
 Contribution Codes
• Can use event contribution code 1 (Primary cause of event) on
additional causes of events during PO and MO events only and
not any forced outages or derates!
• Must use event contribution code 2 to 5 on any additional causes
of events during any forced outage or derate.
208
Primary Event Cause (cont.)
 Time: Work Started/Time: Work Ended
(optional)
• Uses 24 hour clock and looks at event start & end
dates & times.
 Problem Alert (optional)
 Man Hours Worked (optional)
 Verbal Description (optional)
• Most helpful information is in the verbal descriptions
IF they are completed correctly.
209
Types of Failures (III-34, App. H)
 Erosion
 Mechanical
 Corrosion
 Hydraulic
 Electrical
 Instruments
 Electronic
 Operational
(Same as Amplification Codes)
210
Typical Contributing Factors
 Foreign/Wrong Part
 Normal Wear
 Foreign/Incorrect
Material
 Particulate
Contamination
 Lubrication Problem
 Abnormal Wear
 Weld Related
 Set Point Drift
 Abnormal Load
 Short/Grounded
 Abnormal
Temperature
 Improper Previous
Repair
211
Typical Corrective Actions
 Recalibrate
 Replace Part(s)
 Adjust
 Repair Component(s)
 Temporary Repair
 Reseal
 Temporary Bypass
 Repack
 Redesign
 Request License
Revision
 Modify
 Repair Part(s)
212
Compare the difference ...
Method 1
Method 2
 Cause Code 1000
 Cause Code 1000
 U1 Outage
 U1 Outage
 “The unit was brought
off line due to water
wall leak”
 “Leak. 3 tubes eroded
from stuck soot
blower. Replaced
tubes, soot blower
lance.”
213
Additional Cause of Event
 Same layout as primary outage causes
 Used to report factors contributing to the cause
of event, additional work, factors affecting
startup/rampdown
 Up to 46 additional repair records allowed
214
Expanded Data Reporting
(III-36-38, App. H)
 For gas turbines and jet engines
• Optional but strongly encouraged
 Failure mechanism (columns 50-53)
• Same as Amplification Codes
 Trip mechanism (manual or auto) (column 54)
 Cumulative fired hours at time of event (columns 55-60)
 Cumulative engine starts at time of event (columns 6165)
215
Question & Answer
216
Quick Quiz
Question:
Riverglenn #1 (a fossil unit) came down for a boiler
overhaul on March 3rd. What is the appropriate
cause code for this event?
217
Quick Quiz (cont.)
Answer:
1800 - Major Boiler overhaul
• more than 720 hours
1801 - Minor Boiler overhaul
• 720 hours or less
218
Quick Quiz (cont.)
Question:
Riverglenn #2 experienced a turbine overhaul from
September 13 to October 31. A number of components
were planned for replacement, including the reblading
of the high pressure turbine (September 14-October
15). What are the proper Cause Codes and
Contribution Codes for this outage?
219
Quick Quiz (cont.)
Answer:
 Major Turbine overhaul
• Cause Code 4400
• Contribution Code 1
 High-Pressure Turbine reblading
• Cause Code 4012
• Contribution Code 1
220
Quick Quiz (cont.)
Question:
The following non-curtailing event was reported on a 300
MW unit:
• Started January 3 @ 1300
• Ended January 12 @ 0150
• Cause Code 3410 (Boiler Feed Pump)
• Gross Available Capacity: *
• Net Available Capacity: 234 MW
Is everything okay with this description?
221
Quick Quiz (cont.)
Answer:
The capacity of the unit during the NC should not
be reported because the unit was capable of 100%
load. Only report GAC and NAC when the unit is
derated. (See Page III-18, last paragraph.) If GAC
or NAC is reported with an NC, the editing program
shows a “warning” only.
222
Quick Quiz (cont.)
Question:
Riverglenn #1 experienced the following event:
• Event Type: D4
• Start Date/Time: September 3; 1200
• End Date/time: September 4; 1300
• GAC:
• NAC: 355
• Cause Code: 1486
Is this event reported correctly?
223
Quick Quiz (cont.)
Answer:
The GAC is blank, causing an error.
• Put value in GAC space or
• Place * in GAC space
NERC no longer recognizes cause code 1486 (starting in
1993). Use Cause Code 0265 instead.
• See Page Appendix B-6
224
Quick Quiz (cont.)
Question:
Riverglenn #1 experienced a FO as follows:
• Start date/time: October 3 @ 1545
• End date/time: October 3 @ 1321
• GAC:
• NAC:
• Cause Code: 1455
• Description: ID fan vibration, fly ash buildup on blades
Is this event reported correctly?
225
Quick Quiz (cont.)
Answer:
The start time of the event is after the end time.
Looking at the description of the event, the better cause
code would be 1460, fouling of ID Fan rather than just ID
Fan general code 1455.
226
Review of Standard Terms and Definitions
Used by the Electric Industry
227
Lord Keyes said, “If you can’t
measure it, then you can’t improve it.”
The reason we collect information on
the power plants is to measure
it’s performance and improve it
as needed.
228
The “Standard”
 ANSI/IEEE Standard, “Definitions for Use in
Reporting Electric Generating Unit Reliability,
Availability, and Productivity”
 Approved September 19, 1985
 Renewal completed in 2006
 Many parts taken from EEI standard.
 Originally, designed for base-loaded units only!
Now, all types of unit operation!
229
Unit States
230
From the Unit State Chart …
“Unplanned” – corrective action
Forced + Maintenance + Planned
231
From the Unit State Chart …
“Scheduled” - preventive
Forced + Maintenance + Planned
232
Please note …
 Unplanned and scheduled numbers
ARE NOT ADDITIVE!!!!
 Why?
• Maintenance outages in both numbers.
• Use unplanned or scheduled for your uses but don’t
compare them.
233
Two Classes of Equations
1. Time-based
• All events
• Without Outside Management Control (OMC)
2. Capacity- or Energy-based
• All events
• Without Outside Management Control (OMC)
234
Time-based Equations
 Used by industry and
GADS for many years.
 All units are equal no
matter its MW size
because equation is
based on time, not the
capacity of the unit or
units.
500 MW Fossil
50 MW GT
235
Capacity-based Equations
 Used mostly in-house by
industry. Used in one
GADS report for many
years but not is many.
 All units are not equal
because equation is
based on capacity (not
time) of the units.
 In this example, the
500MW unit has 10 times
the impact on the
combination of the 50 &
500 MW units because it
is 10 times bigger.
50 MW GT
500 MW Fossil
236
Outside Management Control (OMC)
237
Outside Management Control (OMC)
 There are a number of outage causes that may
prevent the energy coming from a power
generating plant from reaching the customer.
Some causes are due to the plant operation and
equipment while others are outside plant
management control (OMC).
 GADS needs to track all outages but wants to
give some credit for OMC events.
238
What are OMC Events?
 Grid connection or substation failure.
 Acts of nature such as ice storms, tornados,
winds, lightning, etc
 Acts of terrors or transmission operating/repair
errors
 Special environmental limitations such as low
cooling pond level, or water intake restrictions
239
What are OMC Events?
 Lack of fuels
• water from rivers or lakes, coal mines, gas lines, etc
• BUT NOT operator elected to contract for fuels where
the fuel (for example, natural gas) can be interrupted.
 Labor strikes
• BUT NOT direct plant management grievances
240
More Information?
 Appendix F – Performance Indexes and
Equations
 Appendix K for description of “Outside
Management Control” and list of cause codes
relating to the equation.
241
Time-based Indices
 Equivalent Availability Factor (EAF)
 Equivalent Unavailability Factor (EUF)
 Scheduled Outage Factor (SOF)
 Forced Outage Factor (FOF)
 Maintenance Outage Factor (MOF)
 Planned Outage Factor (POF)
242
Time-based Indices
 Energy Factors
• Net Capacity Factor (NCF)
• Net Output Factor (NOF)
 Rates
• Forced Outage Rate (FOR)
• Equivalent Forced Outage Rate (EFOR)
• Equivalent Forced Outage Rate – Demand (EFORd)
243
Time-based Equations – Factors
244
Equivalent Availability Factor (EAF)
 By Definition:
• The fraction of net maximum generation that could be
provided after all types of outages and deratings
(including seasonal deratings) are taken into account.
• Measures percent of maximum generation available
over time.
• Not affected by load following
• The higher the EAF, the better.
• Derates reduce EAF using Equivalent Derated Hours.
245
What is meant by “Equivalent Derated
Hours?”
 This is a method of
converting deratings into
full outages
 The product of the
Derated Hours and the
size of reduction, divided
by NMC
 100 MW derate for 4
hours is the same loss as
400 MW outage for 1
hour.
100MWx4hours = 400MWx1hour
400
300
200
100
0
1
2
3
4
400
300
200
100
0
1
2
3
4
246
Equivalent Availability Factor (EAF)
EAF = (AH - ESDH - EFDH - ESEDH) x 100%
PH
Where AH=7760; PH=8760; ESDH=50;
EFDH= 500; ESEDH=10; MOH=440
EAF = (8760 – 50 - 500 -10 - 440) x 100% = 88.58%
8760
247
Equivalent Unavailability Factor (EUF)
 Compliment of EAF
 EUF = 100% - EAF
 Percent of time the unit is out of service or
restricted from full-load operation due to forced,
maintenance & planned outages and deratings.
 The lower the EUF the better.
248
Scheduled Outage Factor (SOF)
 By Definition:
• The percent of time during a specific period that a unit
is out of service due to either planned or maintenance
outages.
• Outages are scheduled.
 PO – “Well in Advance”
 MO - Beyond the next weekend.
• A measure of the unit’s unavailability due to planned
or maintenance outages.
• The lower the SOF, the better.
249
Scheduled Outage Factor (SOF)
SOF = 100% x (POH + MOH)
PH
250
Other Outage Factors
 Maintenance Outage Factor (MOF)
MOF = 100% x (MOH)
PH
 Planned Outage Factor (POF)
POF = 100% x (POH)
PH
251
Forced Outage Factor (FOF)
 By Definition:
• The percent of time during a specific period that a
unit is out of service due to forced outages.
• Outages are not scheduled and occur before the next
weekend.
• A measure of the unit’s unavailability due to forced
outages over a specific period of time.
• The lower the FOF, the better.
252
Forced Outage Factor (FOF)
FOF = 100% x (FOH)
PH
253
Net Capacity Factor (NCF)
 By Definition:
• Measures the actual energy generated as a fraction
of the maximum possible energy it could have
generated at maximum operating capacity.
• Shows how much the unit was used over the period
of time.
• The energy produced may be outside the operators
control due to dispatch.
• The higher the NCF, the more the unit was used to
generate power (moving to “base-load”).
254
Net Capacity Factor (NCF)
NCF = 100% x (Net Actual Generation)
[PH x (Net Maximum Capacity)]
255
Net Output Factor (NOF)
 By Definition:
• Measures the output of a generating unit as a function
of the number of hours it was in service (synchronized
to the grid)
• How “hard” was the unit pushed.
• The energy produced may be outside the operators
control due to dispatch.
• The higher the NOF, the higher the loading of the unit
when on-line.
256
Net Output Factor (NOF)
NOF = 100% x (Net Actual Generation)
[SH x (Net Maximum Capacity)]
257
Comparing NCF and NOF
NCF = 100% x (Net Actual Generation)
[PH x (Net Maximum Capacity)]
NOF = 100% x (Net Actual Generation)
[SH x (Net Maximum Capacity)]
NCF measures % of time at full load.
NOF measures the loading of the unit when operated.
258
Comparing AF/EAF/NCF/NOF
NOF > NCF
(Because SH is normally always be less
than PH. What would be the exception?)
AF > EAF > NCF
(What would cause these 3
numbers to be equal? What is
its likelihood of occurring?)
259
What can you learn from the
numbers below?
EAF
NCF
NOF
Nuclear
88.35
89.18
98.81
Fossil, coal
84.19
70.96
84.65
Fossil, gas
86.97
13.33
38.38
Fossil, oil
81.86
15.24
49.03
Gas turbines
90.20
2.67
66.70
Hydro
85.98
41.13
70.53
(Data for 2005-2009 GAR Report)
260
Meeting Demand in Real Time
Typical Daily Demand Curve
Operating Reserves
Peak Load
Intermediate Load
Capacity:
Instantaneous measure of
electricity available at peak
Base Load
Energy:
Electricity Produced over Time
261
What can you learn from the
numbers below?
EAF
NCF
NOF
Age in '09
Nuclear
88.35
89.18
98.81
29.37
Fossil, coal
84.19
70.96
84.65
42.45
Fossil, gas
86.97
13.33
38.38
45.86
Fossil, oil
81.86
15.24
49.03
44.59
Gas turbines
90.20
2.67
66.70
26.96
Hydro
85.98
41.13
70.53
57.81
(Data for 2005-2009 GAR Report)
262
Time-based Equations – Rates
263
Forced Outage Rate
 By Definition:
• The percent of scheduled operating time that a unit is
out of service due to unexpected problems or failures.
• Measures the reliability of a unit during scheduled
operation
• Sensitive to service time
 (reserve shutdowns and scheduled outage influence it)
• Best used to compare similar loads:
– base load vs. base load
– cycling vs. cycling
• The lower the FOR, the better.
264
Forced Outage Rate
Calculation:
FOR =
FOH
FOH + SH + Syn Hrs + Pmp Hrs
x 100%
Comparison: unit with high SH vs. low SH
(SH = 6000 hrs vs. 600 hrs; FOH = 200 hrs)
FOR =
200
= 3.23%
200 + 6000
FOR =
200
200 + 600
= 25.00%
265
Equivalent Forced Outage Rate
 By Definition:
• The percent of scheduled operating time that a unit is
out of service due to unexpected problems or failures
AND cannot reach full capability due to forced
component or equipment failures
• The probability that a unit will not meet its demanded
generation requirements.
• Good measure of reliability
• The lower the EFOR, the better.
266
Equivalent Forced Outage Rate
Calculation:
EFOR =
FOH + EFDH
.
(FOH + SH + Syn Hrs + Pmp Hrs + EFDHRS)
where EFDH = (EFDHSH + EFDHRS)
EFDHSH is Equivalent Forced Derated Hours
during Service Hours.
EFDHRS is Equivalent Forced Derated Hours
during Reserve Shutdown Hours.
267
Equivalent Forced Outage Rate
As an example:
FOH = 750, EFDH = 450, SH = 6482, EDFHRS=0,
Syn Hrs = 0, Pmp Hrs = 0
EFOR =
FOH + EFDH
.
(FOH + SH + EFDHRS )
EFOR =
750 + 450 . = 16.6%
(750 + 6482 + 0 )
268
Equivalent Forced Outage Rate –
Demand (EFORd)
 Markov equation developed in 1970’s
 Used by the industry for many years
• PJM Interconnection (20 years)
• Similar to that used by the Canadian Electricity
Association (20 years)
• Being use by the CEA, PJM, New York ISO, ISO New
England, and California ISO.
269
Equivalent Forced Outage Rate –
Demand (EFORd)
 Interpretation:
• The probability that a unit will not meet its demand
periods for generating requirements.
• Best measure of reliability for all loading types (base,
cycling, peaking, etc.)
• Best measure of reliability for all unit types (fossil,
nuclear, gas turbines, diesels, etc.)
• For demand period measures and not for the full 24hour clock.
• The lower the EFORd, the better.
270
Equivalent Forced Outage Rate –
Demand (EFORd)
11
12
1
2
10
9
3
8
4
7
5
6
271
EFORd Equation:
EFORd= [(FOHd) + (EFDHd)] x 100%
[SH + (FOHd)]
Where: FOHd = f x FOH
f=
[(1/r)+(1/T)]
[(1/r)+(1/T)+(1/D)]
r= FOH/(# of FOH occur.)
T= RSH/(# of attempted Starts)
D= SH/(# of actual starts)
EFDHd = fp x EFDH
fp = SH/AH
272
Example of EFORd vs. EFOR
EFOR vs. EFORd
General Trend
Percent EFOR & EFORd
140
120
EFOR, range from 6.2 to 130.0%
100
80
EFOR
60
EFORd
40
EFORd, range from 4.7 to 30.7%
20
0
Increasing RSH / Decreasing SH
(All other numbers in calculation are contant.)
273
Example of EFORd vs. EFOR
EFOR vs. EFORd
Gas Turbines 2004-2008
100
90
Percent EFOR & EFORd
80
70
60
50
40
30
20
10
0
Corresponding EFOR & EFORd Values
EFORd
EFOR
274
Limiting Conditions for EFORd
Case
SH
FOH
RSH
FORd
EFORd
Base
>0
>0
>0
Applicable
Applicable
1
0
>0
>0
Cannot be
determined
Cannot be
determined
2
0
0
>0
Cannot be
determined
Cannot be
determined
3
0
>0
0
Cannot be
determined
Cannot be
determined
4
>0
0
>0
0
EFDH/AH
5
>0
0
0
0
EFDH/SH
6
>0
>0
0
FOR
EFOR
7
0
0
0
Cannot be
determined
Cannot be
determined
Base case is normal. Cases 4, 5, 6: Computed FORd, EFORd are valid.
275
What can you learn from the
numbers below?
FOR
EFOR
EFORd
SH
RSH
Nuclear
2.16
3.09
3.09 7,864.04
6.03
Fossil, coal
5.37
7.46
7.08 6,988.47
615.3
Fossil, gas
10.37
11.66
7.24 2,506.42 4,891.71
Fossil, oil
15.33
16.42
11.58 2,682.17 4,465.38
Gas turbines
53.73
54.10
5.71
5.93
Hydro
8.86
241.14 7,823.34
5.16 4,972.45 1,907.60
(Data for 2005-2009 GAR Report)
276
How to Avoid Misleading EFORd
 Use a large population of units.
 Use a long period of time if analyzing a single
unit (at least one year.) Monthly FORd or
EFORd may work on some months but not all.
 Check data! If Service Hours is zero, increase
population or period so it is not zero.
277
EAF + EFOR = 100%?
Given: PH = 8760, SH = 10, RSH = 8460. FOH = 290. No deratings
EAF = AF = AH
PH
EFOR = FOR =
EAF = 8470
8760
EFOR =
EAF = 97.7%
EFOR = 97.7%
FOH__
(SH+ FOH)
290____
(290 + 10)
Factors and rates are not additive
and not complementary!
278
Other Equations in IEEE 762
Forced Outage Rate Demand- FORd
FORd =
FOHd
[FOHd + SH]
x 100%
where
FOHd = f 1x FOH
1  1 1 1 


f = r T  / r  T  D 

 

r=Average Forced outage duration = (FOH) / (# of FO occurrences)
D=Average demand time = (SH) / (# of unit actual starts)
T=Average reserve shutdown time = (RSH) / (# of unit attempted
starts)
279
Other Equations in IEEE 762
 Equivalent Maintenance Outage Factor
EMOF = 100% x (MOH + EMDH)
PH
 Equivalent Planned Outage Factor
EPOF = 100% x (POH + EPDH)
PH
 Equivalent Forced Outage Factor
EFOF = 100% x (FOH + EFDH)
PH
280
Other Equations in IEEE 762
 Equivalent Maintenance Outage Rate
EMOR = 100% x (
MOH + EMDH
)
(MOH+SH+Syn Hr+Pmp Hr+EMDHRS)
 Equivalent Planned Outage Rate
EPOR = 100% x
( POH + EPDH
)
(POH+SH+Syn Hr+Pmp Hr+EPDHRS)
 Equivalent Forced Outage Rate
EFOR = 100% x (
FOH + EFDH
)
(FOH+SH+Syn Hr+Pmp Hr+EFDHRS)
281
Question & Answer
282
Comparing EAF, WEAF, XEAF, etc.
EAF = (AH - ESDH - EFDH - ESEDH) x 100%
PH
WEAF = Σ NMC(AH - ESDH - EFDH - ESEDH) x 100%
Σ NMC (PH)
XEAF = (AH - ESDH - EFDH - ESEDH) x 100%
PH
XWEAF = Σ NMC(AH - ESDH - EFDH - ESEDH) x 100%
Σ NMC (PH)
283
Comparing EAF, WEAF, XEAF, etc.
Fossil, All
sizes, coal
Nuclear
Gas Turbines
EAF
84.64%
86.15%
90.28%
WEAF
84.25%
86.64%
90.06%
XEAF
85.21%
86.50%
90.76%
XWEAF
84.74%
86.98%
90.56%
284
Comparing EAF, WEAF, XEAF, etc.
Combination of
Fossil & Gas Turbine
EAF
81.82%
WEAF
83.68%
XEAF
82.68%
XWEAF
84.01%
285
Comparing EAF, WEAF, XEAF
 Time-based is simple to understand and
calculate. Good method for units of the same
MW size.
 Capacity-based is more complicated to
calculate but provides a more accurate view of
total system capabilities, especially for units of
different MW sizes
 OMC-based allows power stations a fair grade
on performance by removing outside influences
on production.
286
Commercial Availability
287
Commercial Availability
 First developed in the United Kingdom but now
used in a number of countries that deregulate
the power industry.
 No equation.
 Marketing procedure for increasing the profits
while minimizing expenditures. The concept is to
have the unit available for generation during
high income periods and repair the unit on low
income periods.
288
Commercial Availability
Unit Available
Not needed for Generation
Not competitive, -$
Unit Available
Needed for Generation
Make Big Revenue, +$
Unit not available
Unit not available
Not Needed for Generation
Needed for Generation
Good time for repairs
Lost opportunity, -$
289
Words About Distributions
290
Beware of Statistical Scatter
 Averages or means can be misleading
• Sample should be at least 30
 Also use median, mode, standard deviation,
range
 Beware of bimodal distributions
• Separate unique populations
 Tools
• pc-GAR, SAS, scatter diagrams, etc.
291
Weighted Equivalent Availability Factor
Fossil-Steam Units in USA for Year 2004-2008 Only
WEAF
10%
25%
50%
Mean
75%
90%
100-199 MW
72.83
82.02
87.58
85.50
91.54
94.82
200-299 MW
76.30
81.91
86.16
84.82
89.44
91.96
300-399 MW
76.14
80.85
86.02
85.12
89.32
91.58
400-499 MW
73.45
80.84
85.92
84.37
89.01
92.71
500-599 MW
74.30
78.88
83.56
82.95
87.37
90.51
600-699 MW
75.39
80.91
85.77
84.87
89.15
91.60
700-799 MW
72.61
76.82
84.09
81.09
88.24
90.88
800-899 MW
82.13
84.65
87.76
87.78
91.70
92.57
292
Weighted Equivalent Availability Factor
Fossil-steam units in USA; 2004-2008
Fossil Unit WEAF by Size
100
90
80
70
WEAF Percent
10%
60
25%
50%
50
Mean
75%
40
90%
30
20
10
0
100-199 200-299 300-399 400-499 500-599 600-699 700-799 800-899
MW
MW
MW
MW
MW
MW
MW
MW
293
WEAF and Age of Fossil Units
All Sizes and Fuels
Fossil-steam units in USA 1982-2008
Fossil Unit Weighted Equiv. Availabliity Factor (WEAF)
and Unit Age
90
70
60
50
AGE
WEAF
40
30
20
10
08
20
06
20
04
20
02
20
00
20
98
19
96
19
94
19
92
19
90
19
88
19
86
19
84
19
82
0
19
% WEAF & Unit AGE in Years
80
294
Words About Pooling Data
295
Words About Pooling Data
 Data pooling means collecting the data of
several units and combining them into one
number
• Average EUF (or CUF), EFORd, NCF, etc
 IEEE Committee on Probabilities and
Applications reviewed methods
• Summarize hours first then divide by number in
sample. Then put results in equation.
• DO NOT average factors, rates, etc.
296
Words About Pooling Data
Example of the proper pooling for FOR for 5 units:
FOH = 840 +
78 + 67 + 117 + 546 = 1648 / 5 = 329.60
SH = 6760 + 7610 + 116 + 765 + 7760 = 23011 / 5 = 4602.20
Average FOR = [FOH/(FOH + SH)] X 100%
= 100% x [329.60/(4602.20+ 329.60)] = 6.62%
*****************************************************
Example of the WRONG pooling of AF for 5 units:
Average FOR = (11.05% + 1.01% + 36.61% + 13.27% + 6.57%)
= 68.51% / 5
= 13.70%
297
GADS Standard for EFORd
 Will follow IEEE recommendation as shown in Appendix
F, Notes 1 and 2.
 Will use Method 2 for calculating EFORd and FORd in all
GADS publications and pc-GAR.
• Consistency – all other GADS equations sum hours in both the
denominator and numerator before division.
• Allow calculations of smaller groups. By allowing sums, smaller
groups of units can be used to calculate EFORd without
experiencing the divide by zero problem (see Note #2 for
Appendix F).
298
Pooling Time-based Statistics
 Equivalent Maintenance Outage Factor
EMOF = 100% x Σ (MOH + EMDH)
Σ PH
 Equivalent Planned Outage Factor
EPOF = 100% x Σ (POH + EPDH)
Σ PH
 Equivalent Forced Outage Factor
EFOF = 100% x Σ (FOH + EFDH)
Σ PH
299
Pooling Weighted Statistics
 Weighted Equivalent Maintenance Outage
Factor
WEMOF = 100% x Σ [(MOH + EMDH) x NMC]
Σ (PH x NMC)
 Weighted Equivalent Planned Outage Factor
WEPOF = 100% x Σ [(POH + EPDH) x NMC]
Σ (PH x NMC)
 Weighted Equivalent Forced Outage Factor
WEFOF = 100% x Σ (FOH + EFDH) x NMC]
Σ (PH x NMC)
300
What’s new with GADS?
301
GADS and the World Energy Council
 GADS is involved with the World Energy Council
(WEC) and its Performance of Generating Plant
(PGP) subcommittee.
• Teaching workshops
• Providing software
• Wanting to create a WEC-GADS database and a
“WEC pc-GAR”
 Continue to explore best way to collect unit specific
data on fossil units worldwide for WEC pc-GAR
software.
302
Continuing Projects
 Adding wind generators to GADS
• Working group formed to determine design,
event, cause codes, etc. for data collection.
• Discussion of wind data collection is on Thursday at
8:00 a.m.
303
Continuing Projects
 Adding wind generators to GADS
• Started database on concentrated solar and PV
earlier this year. Still in the works…
304
Exchange data with Europe and CEA
 Exchange data with Europe and the Canadian
Electricity Association (CEA)
 Continue correspondence with the International
Atomic Power Agency (IAEA)
305
Design Data Time Stamping
306
Design Data Time Stamping
 Tracking changes in plants with time.
 Addition/removal of equipment like bag houses,
mechanical scrubbers, etc.
 Upgrading or changing equipment like pumps,
fans, etc.
 Will be sent out to each reporter by the end of
November this year (if not sooner).
307
Closing Comments
308
Data Transmittal Tools
Media
Specifications
E-mail:
 Text format (.txt). To improve
transmission times your data files may
be submitted as compressed (.zip) files.
 Submit your data within 30-days after
the end of every calendar quarter.
 E-mail your data to:
[email protected]
309
Data Release Guidelines
 Operating companies have access to own data
only.
 Manufacturers have access to equipment they
manufactured only.
 Other organizations do not have access to unitspecific data unless they receive written
permission from the generating company.
 In grouped reports, no report is provided if less
than 7 units from 3 operating companies.
310
Access to pc-GAR
 If you are a generating company in North
America and report your GADS data to NERC,
you can purchase pc-GAR.
 If you are a generating company in North
America and do not report your GADS data to
NERC, you cannot purchase pc-GAR.
 If you are a generating company outside North
America and either do or do not report GADS
data to GADS, you can purchase pc-GAR.
311
Question & Answer
Contact:
Mike Curley
Manager of GADS Services
[email protected]
801.756.0972
312